To meet rising global demands for energy, the oil and gas industry continuously strives to develop innovative oilfield technologies. A large portion of the world's oil and gas reserves are trapped in carbonate reservoirs, particularly in the Middle East. The mineralogy of these heterogeneous carbonate formations primarily consists of calcite, dolomite or combinations thereof. Accordingly, well stimulation treatments for these formations have traditionally relied upon the use of strong mineral acids (live acid), e.g. hydrochloric acid (HCl) ranging in concentration from 15-28 weight percent (wt %). Depending on the reservoir and production challenge associated with it, matrix acidizing or acid fracturing may be employed. Acid fracturing is favored for the stimulation of tight formations where the fluid is injected at a pressure exceeding the formation pressure in order to etch the surface and maintain the continuity of the fractures and create wormholes that propagate deeper into the reservoir. Conversely, matrix acidizing, a procedure in which acid is injected into the reservoir below the formation pressure, is widely used after drilling production wells in order to create a localized distribution of wormholes that are narrow and linear in nature that circumvent the damaged zone. In the field, treatment with fluids like strong mineral acids (e.g., hydrochloric acid (HCl)) is preferred because the fluid reacts with calcite and dolomite to yield products that are readily soluble in water; hence formation damage is negligible. Additionally, the strong mineral acids tend to be economically favorable. Notably, the longevity and practical application of this treatment with strong mineral acid raises serious concerns from both a corrosion standpoint and because the rapid reaction kinetics (rock-HCl) causes the live acid to be spent quickly. As a result of the reaction kinetics, large volumes of acid are required and even still, deeper penetration of live acid into the reservoir is not achieved. An assortment of alternative approaches (e.g. use of organic acids, gelled acids, synthetic acids, etc.) have been proposed to address these challenges, each of which are associated with advantages and disadvantages. Among the most popular is emulsification of HCl in diesel, widely known as conventional emulsified acids. Accordingly, they are classified as a water-in-oil (W/O) emulsions where droplets containing strong mineral acid, i.e. HCl ranging in concentration from 15-28 wt % are present in a continuous hydrocarbon phase (e.g. diesel). Conventional emulsified acids are widely used in the oil and gas industry to stimulate carbonate reservoirs. Emulsions are traditionally stabilized by the addition of amphiphilic surfactant-based emulsifiers. The surfactant stabilized acid emulsions are characterized by a hydrophilic head group and hydrophobic tail that serve as an anchor or bridge between the oil-water interfaces to reinforce the structural integrity of the droplets by minimizing the interfacial tension and lowering the surface energy. In the reservoir, the desired mechanism of delayed acid release is primarily governed by downhole conditions such as the temperature, pressure, pH and capillary forces. These parameters trigger the emulsion droplets to spontaneously break and release concentrated HCl. The live acid then reacts with the carbonate formation to produce a conductive wormhole network which continues until all of the acid is spent. The conventional emulsified acid system is favored because it produces more directional wormholes than a regular HCl acid injection, due to the slower acid-rock reaction kinetics. However, improvements to this system are needed as the former still possess a fast reaction time that results in a high concentration of wormholes near the inlet to the formation because the conventional emulsions still comparatively react quickly with the rock as the fluid is injected.